Degrading and removing cured resins from substrates

ABSTRACT

Methods are provided for chemically removing cured resin product from surfaces and subterranean formations in case of inappropriate consolidation, plugging of screens or tubing, and equipment damage. A chemical solvent is introduced to a wellbore where a resin has cured. The resin is contacted with the chemical solvent until the resin at least partially dissolves. At least a portion of the dissolved resin is then removed from the wellbore.

BACKGROUND

Hydrocarbon wells are often located in subterranean zones that containunconsolidated particulates that may migrate within the subterraneanformation with the oil, gas, water, and/or other fluids produced by awell penetrating the subterranean formation. As used herein, the term“unconsolidated particulate,” and derivatives thereof, includes looseparticulates and particulates bonded with insufficient bond strength towithstand the forces created by the production of fluids through theformation, which may include but are not limited to formation finesand/or proppant particulates. “Formation fine(s),” another term usedherein, refers to any loose particles within the portion of theformation, including, but not limited to, formation fines, formationsand, clay particulates, coal fines, and the like. A similar situationcan exist in certain wells where particulates referred to as “proppantparticulates” may be introduced into the subterranean formation. Theproppant particulates may be used in conjunction with hydraulicfracturing to prevent the fractures from fully closing upon the releaseof hydraulic pressure, forming conductive channels through which fluidsmay flow to the wellbore.

The presence of these unconsolidated particulates in produced fluids maybe disadvantageous and undesirable in that the particulates may abradepumping and other producing equipment and reduce the fluid productioncapabilities of producing zones. Unconsolidated subterranean zonesinclude those that contain loose particulates and those wherein thebonded particulates have insufficient bond strength to withstand theforces produced by the production of fluids through the zones. “Zone” asused herein simply refers to a portion of the formation and does notimply a particular geological strata or composition.

One way to address the disadvantages caused by unconsolidatedparticulates is to introduce a resin into the unconsolidatedsubterranean zone. The term “resin” as used herein refers to any ofnumerous physically similar polymerized synthetics or chemicallymodified natural resins including thermoplastic materials andthermosetting materials. In addition to maintaining a relativelysolids-free production stream, consolidating particulates also aids inprotecting the conductivity of the formation. Such consolidationtreatments involve the injection of a liquid resin into the formationand thereafter causing the resin to cure to an infusible state through aprocess known as thermosetting. The cured resin cements the sand grainsor other unconsolidated particulates together by providing highstrength, and, ideally, retaining a high percentage of initial formationpermeability (“Regain Permeability”).

In certain cases, achieving high consolidation strength can be difficultand may require additional resin to account for large amounts ofunconsolidated particles. However, if an excess amount of resincomposition is pumped to achieve high strength or if there is a delay inthe pumping schedule, the resin can cure in undesirable places,including the formation, screens, tubing, and other equipment. Theexcess resin can also block the formation's permeable channels andreduce the regain permeability. Similarly, consolidated packs of curedresin and particulate can form in undesirable places. The cured resin orconsolidated packs can lead to permanent damage to these locations.

Once resin is cured, it can be difficult to remove. Traditionally, adrill bit or similar mechanical method is used to remove cured resin andconsolidated packs remaining in the wellbore or in the subterraneanformation. However, using these mechanical methods to remove cured resinpresents additional challenges and it is not always possible to removeresin from confined spaces or from the surface of equipment.

BRIEF DESCRIPTION OF THE DRAWING

This drawing illustrates certain aspects of some of the embodiments ofthe present disclosure, and should not be used to limit or define theinvention.

FIG. 1 illustrates an example of a system where certain embodiments ofthe present disclosure may be used.

While embodiments of this disclosure have been depicted, suchembodiments do not imply a limitation on the disclosure, and no suchlimitation should be inferred. The subject matter disclosed is capableof considerable modification, alteration, and equivalents in form andfunction, as will occur to those skilled in the pertinent art and havingthe benefit of this disclosure. The depicted and described embodimentsof this disclosure are examples only, and not exhaustive of the scope ofthe disclosure.

DESCRIPTION OF EMBODIMENTS

The present disclosure provides a method for removing cured resinproduct from subterranean formations, for example, in instances ofundesired consolidation, plugging of screens or tubing, and equipmentdamage.

The methods of the present disclosure generally involve using a chemicalsolvent to remove at least a portion of a cured resin or a consolidatedpack comprising cured resin and particulates. The chemical solvents aretypically used in liquid form, among other reasons, so they canpenetrate confined spaces more easily. One of the potential advantagesof the methods of the present disclosure is that the enhanced ease ofremoving resin may enhance operators' willingness to and/or confidencein using resin system for sand consolidation.

Resins that may be suitable for treatment according to the presentdisclosure include any resins known in the art that are capable offorming a hardened, consolidated mass. Types of suitable resins include,but are not limited to, two component epoxy based resins, novolakresins, polyepoxide resins, phenol-aldehyde resins, urea-aldehyderesins, urethane resins, phenolic resins, furan resins, furan/furfurylalcohol resins, phenolic/latex resins, phenol formaldehyde resins,polyester resins and hybrids and copolymers thereof, polyurethane resinsand hybrids and copolymers thereof, acrylate resins, and mixturesthereof. It is within the ability of one skilled in the art, with thebenefit of this disclosure, to select a suitable resin for use inembodiments of the present disclosure.

Two-Component Epoxy Resins

One resin suitable for treatment according to the present disclosure isa two-component epoxy based resin comprising a hardenable resincomponent and a hardening agent component. The hardenable resincomponent is comprised of a hardenable resin and an optional solvent.The solvent may be added to the resin to reduce its viscosity for easeof handling, mixing and transferring. It is within the ability of oneskilled in the art with the benefit of this disclosure to determine ifand how much solvent may be needed to achieve a viscosity suitable tothe subterranean conditions. Factors that may affect this decisioninclude the geographic location of the well and the surrounding weatherconditions. An alternate way to reduce the viscosity of the liquidhardenable resin is to heat it. This method avoids the use of a solventaltogether, which may be undesirable in certain circumstances. Thesecond component is the liquid hardening agent component, which iscomprised of a hardening agent, a organosilane coupling agent, asurfactant, an optional hydrolyzable ester for, among other things,breaking gelled fracturing fluid films on the proppant particles, and anoptional liquid carrier fluid for, among other things, reducing theviscosity of the liquid hardening agent component. It is within theability of one skilled in the art with the benefit of this disclosure todetermine if and how much liquid carrier fluid is needed to achieve aviscosity suitable to the subterranean conditions.

Examples of hardenable resins that can be used in the hardenable resincomponent include, but are not limited to, organic resins such asbisphenol A diglycidyl ether resin, butoxymethyl butyl glycidyl etherresin, bisphenol A-epichlorohydrin resin, polyepoxide resin, novolakresin, polyester resin, phenol-aldehyde resin, urea-aldehyde resin,furan resin, urethane resin, a glycidyl ether resin, and combinationsthereof. The hardenable resin used is included in the hardenable resincomponent in an amount in the range of from about 60% to about 100% byweight of the hardenable resin component. In some embodiments thehardenable resin used is included in the hardenable resin component inan amount of about 70% to about 90% by weight of the hardenable resincomponent. Selection of a suitable resin may be affected by thetemperature of the subterranean formation to which the fluid will beintroduced. By way of example, for subterranean formations having abottom hole static temperature (“BHST”) ranging from about 60° F. toabout 250° F., two-component epoxy-based resins comprising a hardenableresin component and a hardening agent component containing specifichardening agents may be preferred. For subterranean formations having aBHST ranging from about 300° F. to about 600° F., a furan-based resinmay be preferred. For subterranean formations having a BHST ranging fromabout 200° F. to about 400° F., either a phenolic-based resin or aone-component HT epoxy-based resin may be suitable. For subterraneanformations having a BHST of at least about 175° F., a phenol/phenolformaldehyde/furfuryl alcohol resin may also be suitable.

Any solvent that is compatible with the chosen resin and achieves thedesired viscosity effect is suitable for use according to the methods inthe present disclosure. Some preferred solvents are those having highflash points (e.g., about 125° F.) because of, among other things,environmental and safety concerns. Such solvents include butyl lactate,butylglycidyl ether, dipropylene glycol methyl ether, dipropylene glycoldimethyl ether, dimethyl formamide, diethyleneglycol methyl ether,ethyleneglycol butyl ether, diethyleneglycol butyl ether, propylenecarbonate, butyl alcohol, d-limonene, fatty acid methyl esters, andcombinations thereof. Other preferred solvents include aqueousdissolvable solvents such as, methanol, isopropanol, butanol, glycolether solvents, and combinations thereof. Suitable glycol ether solventsinclude, but are not limited to, diethylene glycol methyl ether,dipropylene glycol methyl ether, 2-butoxy ethanol, ethers of a C2 to C6dihydric alkanol containing at least one C1 to C6 alkyl group, monoethers of dihydric alkanols, methoxypropanol, butoxyethanol,hexoxyethanol, and isomers thereof. Selection of an appropriate solventis dependent on the resin chosen and is within the ability of oneskilled in the art with the benefit of this disclosure.

As described above, use of a solvent in the hardenable resin componentis optional but may be desirable to reduce the viscosity of thehardenable resin component for ease of handling, mixing, andtransferring. It is within the ability of one skilled in the art, withthe benefit of this disclosure, to determine if and how much solvent isneeded to achieve a suitable viscosity. In some embodiments the amountof the solvent used in the hardenable resin component is in the range offrom about 0.1% to about 30% by weight of the hardenable resincomponent. Optionally, the hardenable resin component may be heated toreduce its viscosity, in place of, or in addition to, using a solvent.

Examples of the hardening agents that can be used in the liquidhardening agent component of the two-component consolidation fluidsinclude, but are not limited to, piperazine, derivatives of piperazine(e.g., aminoethylpiperazine), 2H-pyrrole, pyrrole, imidazole, pyrazole,pyridine, pyrazine, pyrimidine, pyridazine, indolizine, isoindole,3H-indole, indole, 1H-indazole, purine, 4H-quinolizine, quinoline,isoquinoline, phthalazine, naphthyridine, quinoxaline, quinazoline,4H-carbazole, carbazole, β-carboline, phenanthridine, acridine,phenathroline, phenazine, imidazolidine, phenoxazine, cinnoline,pyrrolidine, pyrroline, imidazoline, piperidine, indoline, isoindoline,quinuclindine, morpholine, azocine, azepine, 2H-azepine, 1,3,5-triazine,thiazole, pteridine, dihydroquinoline, hexa methylene imine, indazole,amines, aromatic amines, polyamines, aliphatic amines, cyclo-aliphaticamines, amides, polyamides, 2-ethyl-4-methyl imidazole,1,1,3-trichlorotrifluoroacetone, and combinations thereof. The chosenhardening agent often effects the range of temperatures over which ahardenable resin is able to cure. By way of example and not oflimitation, in subterranean formations having a temperature from about60° F. to about 250° F., amines and cyclo-aliphatic amines such aspiperidine, triethylamine, N,N-dimethylaminopyridine,benzyldimethylamine, tris(dimethylaminomethyl) phenol, and2-(N2N-dimethylaminomethyl)phenol are preferred withN,N-dimethylaminopyridine most preferred. In subterranean formationshaving higher temperatures, 4,4′-diaminodiphenyl sulfone may be asuitable hardening agent. Hardening agents that comprise piperazine or aderivative of piperazine have been shown capable of curing varioushardenable resins from temperatures as low as about 70° F. to as high asabout 350° F. The hardening agent used is included in the liquidhardening agent component in an amount sufficient to consolidate thecoated particulates. In some embodiments, the hardening agent used isincluded in the liquid hardenable resin component in the range of fromabout 40% to about 60% by weight of the liquid hardening agentcomponent. In some embodiments, the hardenable resin used is included inthe hardenable resin component in an amount of about 45% to about 55% byweight of the liquid hardening agent component.

An organosilane coupling agent may be used, among other things, to actas a mediator to help bond the resin to formation particulates and/orproppant. Any organosilane coupling agent that is compatible with theresin and facilitates the coupling of the resin to the surface of theparticulates is suitable for use in the resins that may be treatedaccording to the present disclosure. Examples of organosilane couplingagents include, but are not limited to,N-2-(aminoethyl)-3-aminopropyltrimethoxysilane;3-glycidoxypropyltrimethoxysilane; γ-aminopropyltriethoxysilane;N-β-(aminoethyl)-γ-aminopropyltrimethoxysilanes,aminoethyl-N-β-(aminoethyl)-γ-aminopropyl-trimethoxysilanes;γ-ureidopropyl-triethoxysilanes; β-(3-4epoxy-cyclohexyl)-ethyl-trimethoxysilane; andγ-glycidoxypropyltrimethoxysilanes; vinyltrichlorosilane; vinyltris(β-methoxyethoxy) silane; vinyltriethoxysilane; vinyltrimethoxysilane;3-metacryloxypropyltrimethoxysilane; β-(3,4epoxycyclohexyl)-ethyltrimethoxysilane;r-glycidoxypropyltrimethoxysilane;r-glycidoxypropylmethylidiethoxysilane; N-β(aminoethyl)-r-aminopropyl-trimethoxysilane; N-β(aminoethyl)-r-aminopropylmethyldimethoxysilane;3-aminopropyl-triethoxysilane; N-phenyl-r-aminopropyltrimethoxysilane;r-mercaptopropyltrimethoxysilane; Vinyltrichlorosilane; vinyltris(β-methoxyethoxy) silane; Vinyltrimethoxysilane;r-metacryloxypropyltrimethoxysilane; β-(3,4epoxycyclohexyl)-ethyltrimethoxysilane;r-glycidoxypropyltrimethoxysilane;r-glycidoxypropylmethylidiethoxysilane;N-β-(aminoethyl)-r-aminopropyltrimethoxysilane;N-β-(aminoethyl)-r-aminopropylmethyldimethoxysilane;r-aminopropyltriethoxysilane; N-phenyl-r-aminopropyltrimethoxysilane;r-mercaptopropyltrimethoxysilane; and combinations thereof. Theorganosilane coupling agent used is included in the hardening agentcomponent in an amount capable of sufficiently bonding the resin to theparticulate. In some embodiments, the organosilane coupling agent usedis included in the hardenable resin component in the range of from about0.1% to about 3% by weight of the hardening agent component.

Any surfactant compatible with the hardening agent and capable offacilitating the coating of the resin onto particles in the subterraneanformation may be used in the hardening agent component. Such surfactantsinclude, but are not limited to, an alkyl phosphonate surfactant (e.g.,a C12-C22 alkyl phosphonate surfactant), an ethoxylated nonyl phenolphosphate ester, one or more cationic surfactants, and one or morenonionic surfactants. Mixtures of one or more cationic and nonionicsurfactants also may be suitable. The surfactant or surfactants used areincluded in the liquid hardening agent component in an amount in therange of from about 1% to about 10% by weight of the liquid hardeningagent component.

While not required, examples of hydrolysable esters that can be used inthe hardening agent component of the integrated consolidation fluids ofthe present invention include, but are not limited to, a mixture ofdimethylglutarate, dimethyladipate, and dimethylsuccinate; sorbitol;catechol; dimethylthiolate; methyl salicylate; dimethyl salicylate;dimethylsuccinate; ter-butylhydroperoxide; and combinations thereof.When used, a hydrolyzable ester is included in the hardening agentcomponent in an amount in the range of from about 0.1% to about 3% byweight of the hardening agent component. In some embodiments ahydrolysable ester is included in the hardening agent component in anamount in the range of from about 1% to about 2.5% by weight of thehardening agent component.

Use of a diluent or liquid carrier fluid in the hardenable resincomposition is optional and may be used to reduce the viscosity of thehardenable resin component for ease of handling, mixing andtransferring. It is within the ability of one skilled in the art, withthe benefit of this disclosure, to determine if and how much liquidcarrier fluid is needed to achieve a viscosity suitable to thesubterranean conditions. Any suitable carrier fluid that is compatiblewith the hardenable resin and achieves the desired viscosity effects issuitable for use in the present invention. Some preferred liquid carrierfluids are those having high flash points (e.g., about 125° F.) becauseof, among other things, environmental and safety concerns; such solventsinclude butyl lactate, butylglycidyl ether, dipropylene glycol methylether, dipropylene glycol dimethyl ether, dimethyl formamide,diethyleneglycol methyl ether, ethyleneglycol butyl ether,diethyleneglycol butyl ether, propylene carbonate, methanol, butylalcohol, d-limonene, fatty acid methyl esters, and combinations thereof.Other preferred liquid carrier fluids include aqueous dissolvablesolvents such as, methanol, isopropanol, butanol, glycol ether solvents,and combinations thereof. Suitable glycol ether liquid carrier fluidsinclude, but are not limited to, diethylene glycol methyl ether,dipropylene glycol methyl ether, 2-butoxy ethanol, ethers of a C2 to C6dihydric alkanol containing at least one C1 to C6 alkyl group, monoethers of dihydric alkanols, methoxypropanol, butoxyethanol,hexoxyethanol, and isomers thereof. Selection of an appropriate liquidcarrier fluid is dependent on the resin composition chosen and is withinthe ability of one skilled in the art with the benefit of thisdisclosure.

Furan Resins

Another resin suitable for treatment according to the present disclosureis a furan-based resin. Suitable furan-based resins include, but are notlimited to, furfuryl alcohol resins, mixtures furfuryl alcohol resinsand aldehydes, and a mixture of furan resins and phenolic resins. Ofthese, furfuryl alcohol resins are preferred. A furan-based resin may becombined with a solvent to control viscosity if desired. Suitablesolvents for use in the furan-based consolidation fluids of the presentinvention include, but are not limited to isopropyl alcohol, 2-butoxyethanol, butyl lactate, butyl acetate, tetrahydrofurfuryl methacrylate,tetrahydrofurfuryl acrylate, esters of oxalic, maleic and succinicacids, and furfuryl acetate. Of these, 2-butoxy ethanol is preferred.

Phenolic Resins

Still another resin suitable for treatment according to the presentdisclosure is a phenolic-based resin. Suitable phenolic-based resinsinclude, but are not limited to, terpolymers of phenol, phenolicformaldehyde resins, and a mixture of phenolic and furan resins. Ofthese, a mixture of phenolic and furan resins is preferred. Aphenolic-based resin may be combined with a solvent to control viscosityif desired. Suitable solvents for use in the phenolic-basedconsolidation fluids of the present invention include, but are notlimited to butyl acetate, butyl lactate, furfuryl acetate, and 2-butoxyethanol. Of these, 2-butoxy ethanol is preferred.

Aqueous-Based Resin Consolidation System

In certain embodiments, the resin treated according to the presentdisclosure may be introduced through the wellbore in the form of aconsolidation fluid comprising an aqueous base, an emulsified resin, anda hardening agent. The aqueous base fluids used in the consolidationfluid may comprise fresh water, saltwater, brine (e.g., saturatedsaltwater), seawater, or combinations thereof, and may be from anysource, provided that they do not contain components that mightadversely affect the stability and/or performance of the consolidationfluid. The hardening agent may comprise any of the hardening agentsidentified above.

Any of the resins identified above may be introduced through thewellbore as an emulsified resin. In some embodiments, the emulsifiedresin may be emulsified prior to being suspended or dispersed in theaqueous base fluid. By using a resin emulsifier prior to being suspendedor dispersed in the aqueous base fluid, particular embodiments may offerthe advantage of easier handling and require less preparation in thefield. Examples of suitable emulsifying agents may include, but are notlimited to, surfactants, proteins, hydrolyzed proteins, lipids,glycolipids, and nano-sized particulates, such as fumed silica.

Generally, the emulsified resin may be provided in any suitable form,including particle form, which may be a solid and/or liquid. In thoseembodiments where the resin is provided in a particle form, the size ofthe particle can vary widely. In some embodiments, the resin particlesmay have an average particle diameter of about 0.01 micrometers (“μm”)to about 500 μm. In some embodiments, the resin particles may have anaverage particle diameter of about 0.1 μm to about 100 μm. In someembodiments, the resin particle may have an average particle diameter ofabout 0.5 μm to about 10 The size distribution of the resin particlesused in a particular composition or method may depend upon severalfactors including, but not limited to, the size distribution of theparticulates present in the subterranean formation, the effectiveporosity and/or permeability of the subterranean formation, pore throatsize and distribution, and the like.

Treatment of the Cured Resin

In certain embodiments, the uncured resin or its constituent componentsare introduced through the wellbore to the unconsolidated subterraneanformation. The resin is then cured using methods that are known in theart. In certain embodiments, curing refers to the toughening orhardening of a resin material by cross-linking the molecular chains,which can be brought about by chemical additives such as a hardener inpresence of heat, catalysts, ultraviolet radiation, or an electron beam.The cured resin may consolidate portions of the subterranean formationand may coat the surface of the wellbore. The resin may also form aconsolidated pack of cured resin and particulate. In certainembodiments, the cured resin treated using methods of the presentdisclosure may not be completely hardened but may be at least partiallycured in a manner that provides some degree of consolidation of theparticulates with which it interacts.

All or a portion of the cured resin may subsequently be removed by usinga chemical solvent. The chemical solvent is introduced through thewellbore after the resin is cured. This solvent contacts the cured resinand/or consolidated pack and at least partially dissolves it. In certaincases, the cured resin may be completely dissolved. The dissolved resinand consolidated pack may then be safely removed from the wellbore. Forexample, the chemical solvent may be pumped directly into the formationssurrounding the wellbore or into the proppant pack of a propped fractureof one or more selected intervals. The wellbore is shut in for a periodof time to allow the chemical solvent to be in contact with the curedresin located in the formation or proppant pack interval. After the shutin period, the well is allowed to flow back, or alternatively, a wellservicing fluid is injected into the wellbore at the interval whilecirculating back to remove the chemical solvent and dissolved resin.

The chemical solvent is placed into contact with the resin and/orconsolidated pack for a duration of time sufficient to at leastpartially dissolve the resin and/or consolidated pack. In oneembodiment, the chemical solvent is placed into contact with the resinand/or consolidated pack for up to 96 hours. In another embodiment, thechemical solvent is placed into contact with the resin and/orconsolidated pack for as long 120 hours. With the benefit of thisdisclosure, a person of skill in the art can determine the optimalamount of time for the chemical solvent to be in contact with the resinbased on, for example, the type of resin used, the temperature and/orpressure conditions in the well bore, and/or other factors. With thebenefit of the disclosure, a person of skill in the art may adjust theamount of time during the course of a treatment depending upon, forexample, the observed progress of the treatment and/or other factors.

In certain embodiments, the chemical solvent may be introduced into thewellbore using one or more pumps. The chemical solvent may be introducedinto the wellbore with or without a carrier fluid. When used, thecarrier fluid may comprise any fluid that is not incompatible with thechemical solvent. Examples of suitable carrier fluids include water,brine, alcohols, ethers, and other liquids in which the chemical solventis miscible. In most circumstances, strong acids, strong bases,oxidizers, and reducing agents should be avoided. In one embodiment, thechemical solvent comprises about 0.5% to 100% of the fluid in thewellbore by mass. In a preferred embodiment, the chemical solventcomprises about 50% to 100% of the fluid in the wellbore by mass. Insome embodiments, the carrier fluid may include a pH-adjusting agent.

A variety of chemical solvents may be used to at least partiallydissolve the cured resin and/or consolidated pack. Examples of solventsthat may be suitable for use in the methods of the present disclosureinclude amides including lactams such as β-lactam, γ-lactam, δ-lactam,and 8-lactam, and their derivatives such as 2-pyrrolidone,N-methylpyrrolidone (NMP), 1,3-dimethyl-2-imidazolidinone (DMI), orcaprolactam. Other examples of solvents that may be suitable for use inthe methods of the present disclosure include cyclic ketones such ascyclohexanone, cyclopentanone and their derivatives. The solvents may beused individually or in combination.

Treating a cured resin with a chemical solvent according to the methodsof the present disclosure may remove permanent damage caused by excessand improper resin treatments. In certain embodiments, the methods ofthe present disclosure may be used to remove resin from downholeequipment including, but not limited to, screens and tubing. Moreover,in certain embodiments, these methods may be performed without anypreflush (conditioning) fluids before the solvent treatment as thesolvent is compatible with hydrocarbons. In other embodiments, preflushfluids or treatments may be used. The methods of the present disclosurecan be used to save the cost of replacing tubular and completion parts.

In certain embodiments, the methods of the present disclosure may beused to repair a damaged consolidated proppant pack. For example, if aconsolidated proppant pack has been treated with an excess amount ofresin, the excess resin can restrict the flow path for fluids betweenthe individual proppant particulates in the consolidated proppant pack.Treating the damaged consolidated proppant pack according to the methodsof the present disclosure may restore the flow path by removing theexcess resin.

In certain embodiments, the methods of the present disclosure may beused to facilitate the isolation and treatment of a particular zone inthe wellbore and/or subterranean formation. For example, a resin may beintroduced into the wellbore to form a plug and subsequently allowed tocure. This cured resin plug may be used to isolate a zone of thewellbore and/or subterranean formation. In certain embodiments, aparticular zone of the wellbore may be treated according to methodsknown in the art. Following treatment, the cured resin plug may beremoved according to the methods of the present disclosure.

The exemplary chemicals disclosed herein may directly or indirectlyaffect one or more components or pieces of equipment associated with thepreparation, delivery, recapture, recycling, reuse, and/or disposal ofthe disclosed chemicals. For example, and with reference to FIG. 1, thedisclosed chemicals may directly or indirectly affect one or morecomponents or pieces of equipment associated with an exemplary mixingassembly 100, according to one or more embodiments. As one skilled inthe art would recognize, the mixing assembly 100 may be used withland-based or sea-based operations.

The mixing assembly 100 may be used to perform an on-the-fly resincoating process during a hydraulic fracturing treatment. As illustrated,the mixing assembly 100 may include a liquid resin skid 110, a sandtransport 120, a liquid gel 130, a fracturing additive 140, a fracturingblender 150 and a booster pump 160. In particular, resin from the liquidresin skid 110, sand or other proppant particulates from the sandtransport 120, the liquid gel 130, and the fracturing additive 140 arecombined in the fracturing blender 150 to form a proppant slurry. Thebooster pump 160 pumps the slurry to the wellbore where it is pumpeddownhole with high pressure pump(s).

The liquid resin skid 110 may include a liquid resin 112 and a hardener114. Suitable examples include those liquid resins and hardenersdiscussed earlier in this application. The liquid resin 112 and hardener114 are combined by the static mixer 115 to form a homogeneous mixturebefore they are introduced into the fracturing blender 150.

The fracturing blender 150 may include a sand hopper 152, a sand screw154, and a blender tub 156. Sand or other proppant particulates may betransferred from the sand transport 120 to the sand hopper 152. Fromthere, the sand screw 154 may transfer the sand or other proppantparticulates to the blender tub 156. In the blender tub 156, the sand orother proppant particulates may be mixed with the resin and othercomponents to form a resin-coated particulate slurry that is ready to bepumped downhole.

As discussed earlier, situations may occur where an excess of resin isused to coat the proppant particulates or is otherwise introduced intothe subterranean formation. In these circumstances, the chemicalsolvents of the present disclosure may subsequently be pumped into thesubterranean formation to dissolve the resin, for example, according tothe methods disclosed herein of the previously described embodiments.The chemical solvents may be pumped into the wellbore using a variety ofpumps including, for example, liquid additive pumps to deliver thechemical solvents from their containers and positive displacement pumpsto place the chemical solvents into the wellbore.

To facilitate a better understanding of the present disclosure, thefollowing examples of certain aspects of some embodiments are given. Inno way should the following examples be read to limit or define thescope of the invention.

EXAMPLES Example 1

An unconsolidated 20/20 sand was treated with Expedite® 225 resin system(a resin product available from Halliburton Energy Services) and allowedto cure at 200° F. over time for complete curing of the resin. Thecompressive strength of the core was determined to be approximately 2000psi. The core was then cut into four quarters and three of the quarterswere placed into separate jars. Approximately 50 cc of LCA-1 (aliphatichydrocarbons) were added to the first jar containing a quarter of thecore. Approximately 50 cc of Targon® II (an solvent available fromHalliburton Energy Services, comprising N-methyl pyrrolidone as theactive ingredient) were added to the second jar containing a quarter ofthe core. And approximately 50 cc of cyclohexanone were added to thethird jar containing a quarter of the core. The three jars were thenplaced into a water bath at 140° F. and monitored over time.

After three days at temperature, the consolidated cores that weresubmerged in Targon® II and cyclohexanone solvents were collapsed intounconsolidated sand. The previously cured resin had solubilized in thesolvent systems. In contrast, the consolidated core in submerged inaliphatic hydrocarbons LCA-1 remained intact, suggesting the resinsystem is stable under hydrocarbons.

Therefore, the present disclosure is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent disclosure may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. While numerous changes may be made bythose skilled in the art, such changes are encompassed within the spiritof this invention as defined by the appended claims. Furthermore, nolimitations are intended to the details of construction or design hereinshown, other than as described in the claims below. It is thereforeevident that the particular illustrative embodiments disclosed above maybe altered or modified and all such variations are considered within thescope and spirit of the present invention. In particular, every range ofvalues (e.g., “from about a to about b,” or, equivalently, “fromapproximately a to b,” or, equivalently, “from approximately a-b”)disclosed herein is to be understood as referring to the power set (theset of all subsets) of the respective range of values. The terms in theclaims have their plain, ordinary meaning unless otherwise explicitlyand clearly defined by the patentee.

An embodiment of the present disclosure is a method comprising:introducing a chemical solvent into a wellbore penetrating a portion ofa subterranean formation wherein a resin has been at least partiallycured; wherein the chemical solvent is selected from the groupconsisting of β-lactam, γ-lactam, δ-lactam, and ε-lactam, 2-pyrrolidone,N-methylpyrrolidone (NMP), 1,3-dimethyl-2-imidazolidinone (DMI),caprolactam, cyclohexanone, cyclopentanone, any combination thereof, andany derivative thereof; contacting the resin with the chemical solventto at least partially dissolve the resin; and circulating a fluid in thewellbore to remove at least a portion of the resin from the wellbore.Optionally, the chemical solvent comprises N-methylpyrrolidone.Optionally, the resin comprises a two-component epoxy resin. Optionally,the resin is contacted with the chemical solvent for at least 30minutes. Optionally, the chemical solvent is introduced into thewellbore using a carrier fluid, wherein the chemical solvent is presentin the carrier fluid in a range of about 0.5% to about 99%. Optionally,the carrier fluid further comprises a pH-adjusting agent. Optionally,the chemical solvent is introduced into the wellbore using one or morepumps.

Another embodiment of the present disclosure is a method comprising:introducing a chemical solvent into a wellbore penetrating aconsolidated portion of a subterranean formation that has been at leastpartially consolidated with a resin; wherein the chemical solvent isselected from the group consisting of β-lactam, γ-lactam, δ-lactam, andε-lactam, 2-pyrrolidone, N-methylpyrrolidone (NMP),1,3-dimethyl-2-imidazolidinone (DMI), caprolactam, cyclohexanone,cyclopentanone, any combination thereof, and any derivative thereof;contacting the consolidated portion of the subterranean formation withthe chemical solvent to at least partially unconsolidate theconsolidated portion of the subterranean formation. Optionally, thechemical solvent comprises N-methylpyrrolidone. Optionally, the resincomprises a two-component epoxy resin. Optionally, the formation iscontacted with the chemical solvent for at least 30 minutes. Optionally,the chemical solvent is introduced into the wellbore using a carrierfluid, wherein the chemical solvent is present in the carrier fluid in arange of about 0.5% to about 99%. Optionally, the carrier fluid furthercomprises a pH-adjusting agent. Optionally, the chemical solvent isintroduced into the wellbore using one or more pumps.

Another embodiment of the present disclosure is a method comprising:introducing a chemical solvent into a subterranean formation containinga consolidated proppant pack; wherein the consolidated proppant packcomprises a plurality of proppant particles and a resin, and wherein theresin has at least partially consolidated the proppant pack; wherein thechemical solvent is selected from the group consisting of β-lactam,γ-lactam, δ-lactam, and ε-lactam, 2-pyrrolidone, N-methylpyrrolidone(NMP), 1,3-dimethyl-2-imidazolidinone (DMI), caprolactam, cyclohexanone,cyclopentanone, any combination thereof, and any derivative thereof; andcontacting the consolidated proppant pack with the chemical solvent toat least partially unconsolidate the consolidated proppant pack.Optionally, the consolidated proppant pack comprises an excess of resinthat restricts a flow path between the proppant particulates.Optionally, the chemical solvent comprises N-methylpyrrolidone.Optionally, the resin comprises a two-component epoxy resin. Optionally,the chemical solvent is introduced into the subterranean formation usinga carrier fluid, wherein the chemical solvent is present in the carrierfluid in a range of about 0.5% to about 99%. Optionally, the carrierfluid further comprises a pH-adjusting agent.

What is claimed is:
 1. A method comprising: introducing a chemicalsolvent into a wellbore penetrating a portion of a subterraneanformation wherein a resin has been at least partially cured; wherein thechemical solvent is selected from the group consisting of β-lactam,γ-lactam, δ-lactam, and ε-lactam, 2-pyrrolidone, N-methylpyrrolidone(NMP), 1,3-dimethyl-2-imidazolidinone (DMI), caprolactam, cyclohexanone,cyclopentanone, any combination thereof, and any derivative thereof;contacting the resin with the chemical solvent to at least partiallydissolve the resin; and circulating a fluid in the wellbore to remove atleast a portion of the resin from the wellbore.
 2. The method of claim 1wherein the chemical solvent comprises N-methylpyrrolidone.
 3. Themethod of claim 1 wherein the resin comprises a two-component epoxyresin.
 4. The method of claim 1 wherein the resin is contacted with thechemical solvent for at least 30 minutes.
 5. The method of claim 1wherein the chemical solvent is introduced into the wellbore using acarrier fluid, wherein the chemical solvent is present in the carrierfluid in a range of about 0.5% to about 99%.
 6. The method of claim 5wherein the carrier fluid further comprises a pH-adjusting agent.
 7. Themethod of claim 1 wherein the chemical solvent is introduced into thewellbore using one or more pumps.
 8. A method comprising: introducing achemical solvent into a wellbore penetrating a consolidated portion of asubterranean formation that has been at least partially consolidatedwith a resin; wherein the chemical solvent is selected from the groupconsisting of β-lactam, γ-lactam, δ-lactam, and ε-lactam, 2-pyrrolidone,N-methylpyrrolidone (NMP), 1,3-dimethyl-2-imidazolidinone (DMI),caprolactam, cyclohexanone, cyclopentanone, any combination thereof, andany derivative thereof; contacting the consolidated portion of thesubterranean formation with the chemical solvent to at least partiallyunconsolidate the consolidated portion of the subterranean formation. 9.The method of claim 8 wherein the chemical solvent comprisesN-methylpyrrolidone.
 10. The method of claim 8 wherein the resincomprises a two-component epoxy resin.
 11. The method of claim 8 whereinthe formation is contacted with the chemical solvent for at least 30minutes.
 12. The method of claim 8 wherein the chemical solvent isintroduced into the wellbore using a carrier fluid, wherein the chemicalsolvent is present in the carrier fluid in a range of about 0.5% toabout 99%.
 13. The method of claim 12 wherein the carrier fluid furthercomprises a pH-adjusting agent.
 14. The method of claim 8 wherein thechemical solvent is introduced into the wellbore using one or morepumps.
 15. A method comprising: introducing a chemical solvent into asubterranean formation containing a consolidated proppant pack; whereinthe consolidated proppant pack comprises a plurality of proppantparticles and a resin, and wherein the resin has at least partiallyconsolidated the proppant pack; wherein the chemical solvent is selectedfrom the group consisting of β-lactam, γ-lactam, δ-lactam, and ε-lactam,2-pyrrolidone, N-methylpyrrolidone (NMP), 1,3-dimethyl-2-imidazolidinone(DMI), caprolactam, cyclohexanone, cyclopentanone, any combinationthereof, and any derivative thereof; and contacting the consolidatedproppant pack with the chemical solvent to at least partiallyunconsolidate the consolidated proppant pack.
 16. The method of claim 15wherein the consolidated proppant pack comprises an excess of resin thatrestricts a flow path between the proppant particulates.
 17. The methodof claim 15 wherein the chemical solvent comprises N-methylpyrrolidone.18. The method of claim 15 wherein the resin comprises a two-componentepoxy resin.
 19. The method of claim 15 wherein the chemical solvent isintroduced into the subterranean formation using a carrier fluid,wherein the chemical solvent is present in the carrier fluid in a rangeof about 0.5% to about 99%.
 20. The method of claim 19 wherein thecarrier fluid further comprises a pH-adjusting agent.